Method for measurement of hydrocarbon content of tight gas reservoirs

ABSTRACT

Nuclear magnetic resonance (NMR) well logs are obtained from a well in the reservoir measures of the total fluid, including both water and hydrocarbon, in the shale of the reservoir. NMR measurement at the surface of shale subsurface samples obtained in from drill cuttings or core samples of the same well provide measures of total water content of the shale. At the surface, pressure on the subsurface sample becomes that of atmospheric pressure, and hydrocarbon gas contained in the shale cuttings bleeds off. The remaining fluid within the shale cuttings is then only water, which can be measured using NMR techniques. Compensation for the effect of drilling fluids (drilling mud) on the NMR measures from the fluid cuttings is also performed. The hydrocarbon gas content of the formation shale can be determined from the difference between formation NMR well log readings and NMR measurements from subsurface sample.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates to evaluation of subsurface hydrocarbonreservoirs, and more particularly forming measures of the hydrocarboncontent of tight gas reservoirs including shales, tight siliciclasticsands, and tight carbonates.

2. Description of the Related Art

In reservoir engineering, it has been important for reservoir evaluationto have as the starting point a measure of reserve or gas-in-place in agas reservoir and volatile oil reservoir. However, for shale gas, so faras is known, no accurate method has been commonly accepted by theindustry to estimate gas-in-place in a reservoir.

Existing methods have been based on above measures of water bylaboratory testing of core samples obtained from cores extracted fromsubsurface formations by core sampling tools. There have been severaldeficiencies with existing methods. Obtaining cores with core samplingtools at depths of interest in a formation is expensive. Side-wall coresare thus generally only obtained at a few sporadic locations from awell. In addition once the cores have been obtained, their preservationto maintain fluid content for accurate results during ongoing laboratoryevaluation and analysis of the reservoir has been notoriously difficultand full of uncertainty.

For unconventional shale gas reservoirs the presence of organic matter,in addition to the complex mineralogical composition, complicates thelog based methods: the uncertainty in quantity and density of organicmatter and other heavy minerals, such as pyrite, makes the densityporosity inaccurate.

The large amount of hydrogen in organic matter and clay bound waterleads to porosity estimation from neutron logs much higher than the realvalue. Resistivity logs fail to estimate water content in shale due tothe presence of large amounts of clay and the associated surfaceconductivity. This excess conductivity must be accounted for. However,for clay rich shales, accounting for this excess conductivity can leadto large uncertainties in the computed water volumes.

For the core-measurement based methods, the basic porosity measurementin tight nanoporous shales is problematic. The extremely smalldimensions of the pores make it difficult to clean and dry the pores. Ifthe pores are not cleaned and dried, conventional porosity measurementmethods do not provide accurate porosities. For example if the poresremain filled with water, it is not possible to expand helium into thepore space and quantitatively determine how much pore space there is inthe sample.

Even when the porosity is accurately obtained, it remains difficult toestimate the hydrocarbon content based on porosity because a hydrocarbonstorage model is required, which has not been reliably established.Shale contains three type of porosity, namely mineral-matrix porosity,organic-matter porosity, and fracture pores. It is not clear ifhydrocarbon and/or water are present in all or only some of these poresin the reservoir. In addition, the adsorption on the pore surface cancontribute a significant amount of reserve in a nanoporous system.However, the amount of adsorbed hydrocarbon at the reservoir conditionmay not be readily obtained from a laboratory measurement because allthe pore surfaces, including those pores that only hold water in thereservoir, can contribute to the laboratory measurement. Furthermore,the presence of heavy hydrocarbons may result in capillary condensationin some shale gas reservoirs. In this condition, pore surface propertyand pore size distribution significantly impact the hydrocarbon inplace. Therefore, laboratory measured porosity only has some guidancevalue in the estimation of hydrocarbon content for shale gas reservoir.

SUMMARY OF THE INVENTION

Briefly, the present invention provides a new and improved method ofdetermining hydrocarbon gas content of a subsurface shale formation inthe earth. Nuclear magnetic resonance well log measures are obtainedfrom a well in the subsurface shale formation, and a measure of thetotal fluid content in situ of the subsurface shale formation isobtained from these nuclear magnetic resonance well log measures.

Samples of the subsurface shale formation are obtained, and nuclearmagnetic resonance measures are obtained from the subsurface samples. Ameasure of the water content in the subsurface samples is obtained fromthe nuclear magnetic resonance measures from the subsurface samples inthe presence of drilling mud. The hydrocarbon gas content of the shaleformation is determined from the measure of the total fluid content insitu of the subsurface shale formation and measure of the water contentin the formation samples.

The present invention also provides a new and improved computerimplemented method of determining hydrocarbon gas content of asubsurface shale formation in the earth. A measure is formed of thefluid content in situ of the subsurface shale formation obtained by anuclear magnetic resonance well log from a well in the subsurface shaleformation. Measures are formed of the volume of total fluids present insamples of the well from the subsurface shale formation based on nuclearmagnetic resonance spectra obtained from the samples.

Measures are formed of the volume of water present in the subsurfacesample based on nuclear magnetic resonance spectra obtained from thesamples, measures of the weight, and measures of the volume of the drillfluids in the samples. A measure of the water content in the samples isformed, and the hydrocarbon gas content of the shale formation isdetermined from the measure of the fluid content in situ of thesubsurface shale formation and measure of the water content in thesamples.

The present invention also provides a new and improved data processingsystem for determining hydrocarbon gas content of a subsurface shaleformation in the earth based on nuclear magnetic resonance measures. Thedata processing system includes a computer memory, which stores, asinputs, nuclear magnetic resonance well log measures obtained from awell in the subsurface shale formation. The computer memory also storesas inputs a measure of the fluid content in situ of the subsurface shaleformation obtained from the well in the subsurface shale formation, andmeasures of the water content in the samples.

The data processing system according to the present invention alsoincludes a processor, which forms a measure of the fluid content in situof the subsurface shale formation based on nuclear magnetic resonancewell log measures obtained by a nuclear magnetic resonance well log froma well in the subsurface shale formation. The processor also formsmeasures of the volume of total fluids present in the samples from thesubsurface shale formation based on nuclear magnetic resonance spectraobtained from nuclear magnetic resonance measures of the samples.

The processor forms measures of the volume of water present in drillcuttings of the subsurface sample based on nuclear magnetic resonancespectra obtained from nuclear magnetic resonance measures of thesamples, measures of the weight, and measures of the volume of drillfluids in the samples. The processor then determines the hydrocarbon gascontent of the shale formation from the measure of the fluid content insitu of the subsurface shale formation and measure of the water contentin the samples.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic diagram view taken partly in cross-section of awell logging tool for obtaining nuclear magnetic resonance (NMR)measurements at depths of interest in a well in subsurface formationsaccording to the present invention.

FIG. 2 is a plot of densities of methane as a function of pressure forseveral example temperatures.

FIG. 3 is a plot of densities of water as a function of pressure forseveral example temperatures.

FIG. 4 is a plot of an example nuclear magnetic resonance transverserelaxation spectrum for a drilling mud.

FIG. 5 is a plot of an example nuclear magnetic resonance transverserelaxation spectrum for a sample of shale cuttings and drilling mud.

FIG. 6 is a schematic diagram of a process for measurement ofhydrocarbon content of shale gas reservoir according to the presentinvention.

FIG. 7 is a functional block diagram of a set of data processing stepsperformed in a data processing system for measurement of hydrocarboncontent of shale gas reservoir according to the present invention.

FIG. 8 is a schematic block diagram of a data processing system formeasurement of hydrocarbon content of shale gas reservoir according tothe present invention.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

In the drawings, a conventional well logging system W is shown in FIG. 1at a well 10. A sonde 12 containing a nuclear magnetic resonance or NMRwell logging system 14 with conventional processing and surfacecommunication instrumentation is lowered by a conductive wireline cable16 into a well bore 18 to obtain the responses of subsurface formations20 at depths of interest. In the context of the present invention, theformations of interest are tight gas reservoirs in formations containingmethane and other hydrocarbon gases. According to the present invention,tight gas reservoirs include shales, tight siliciclastic sands and tightcarbonates.

NMR logging measures the induced magnetization of hydrogen nuclei(protons) contained within the fluid-filled pore space of porous media(reservoir rocks). Low frequency (in a spectrum from about a few hundredkHz to about a few mHz) NMR-logging measurements respond to the presenceof mobile hydrogen protons, rather than measuring both the rock matrixand fluid properties of formations. Because the mobile protons primarilyoccur in pore fluids, nuclear magnetic resonance effectively responds tothe volume, composition, viscosity, and distribution of hydrogencontaining fluids, which for the purposes of reservoir evaluation are:oil, hydrocarbon gas and water.

During the well logging runs, the sonde 12 and cable 16 are suitablysupported, by a sheave wheel 22. The NMR well logging measurementsobtained by the well logging system 14 are recoded as functions ofborehole depth and transferred to the surface over wireline cable 16 toa suitable data memory as input data for a data processing system D(FIG. 8). As will be set forth, the NMR well logging measurements areprocessed in the data processing system D according to the presentinvention to determine measures of hydrocarbon content of shale gasreservoir in formations of interest. The processed results from dataprocessing system D are then available for analysis by reservoirengineers or analysts.

Nomenclature

In the following description, symbols are utilized which have thefollowing meanings:

Φ_(well log) ^(NMR) Total measured fluid Φ_(HC) Total hydrocarbon Φ_(H)₂ _(O) Water content in the rock Φ_(cuttings) ^(NMR) Fluid content ofthe cuttings v_(pm) Measured fluid volume of the drilling mud W_(pm)Total weight of the drilling mud V_(pm) Total volume of the drilling mudX_(m) ^(w) Fluid content in unit weight of the pure drilling mud X_(m)^(v) Fluid content in unit volume of the pure drilling mud α Ratio ofthe short, small T₂ peaks to the long, large peaks of the pure drillingmud v_(pm) ^(s) Volume of short, small T₂ peaks of pure drilling mudv_(pm) ^(l) Volume of long, large T₂ peaks of pure drilling mud v_(c+m)Volume of total measured fluid v_(w) Volume of water in drill cuttingsv_(m) Volume of fluid from drilling mud v_(c+m) ^(s) Volume of short,small T₂ peaks of total fluid v_(c+m) ^(l) Volume of long, large T₂peaks of total fluid W_(m) Weight of drilling mud in total fluid V_(m)Volume of drilling mud in total fluid W_(c) Weight of water in thecuttings V_(c) Volume of water in cuttings Φ_(dc) ^(NMR) Water in thedrill cutting W_(c+m) Total weight of cuttings and mud V_(c+m) Totalvolume of cuttings and mud

Fluid Content in the Reservoir Condition Measured by NMR Log

The pore pressure for a typical shale gas reservoir is larger than 4,000psi. At this pressure, the methane density as a shale gas is more than100 kg/m³. The real density of hydrocarbon in the pores of shale can behigher than predicted by the bulk state equation. First, the density ofadsorbed hydrocarbon on the nanopore surface in kerogen has a densityclose to liquid at reservoir pressure. Thus, the average hydrocarbondensity in the porous system would be higher than in a pure gas state atthe given pressure and temperature. If other heavier hydrocarboncompounds are extant in the reservoir and capillary condensation hasoccurred, then the hydrocarbon density is close to that of liquid, about500 kg/m³. The density is somewhere within the rectangle 30 of FIG. 2.FIG. 2 is a plot of densities of methane as a function of pressure forseveral example temperatures.

In the density measures shown in FIG. 2, surface adsorption and possiblecapillary condensation have been considered. At this density, thehydrocarbon gas can be easily measured by the NMR logging system 14.

At reservoir conditions, the water density is about 10% smaller than thedensity at surface conditions. FIG. 3 is a plot of densities of water asa function of pressure for several example temperatures. From FIG. 3 itis apparent that temperature has a much greater impact on density ofwater than pressure. As shown in FIG. 3, water density at reservoirconditions is in a range indicated by a rectangle 32. An ellipse 34 inFIG. 3 illustrates a range of water densities at earth surfaceconditions. Water presence in a shale formation can thus be easilymeasured by NMR logging system 14. Therefore, the total measured fluid,Φ_(well log) ^(NMR), can be expressed as:Φ_(well log) ^(NMR)=Φ_(HC)+Φ_(H) ₂ _(O)   (1)in which Φ_(HC) and Φ_(H) ₂ _(O) represent the total hydrocarbon andwater content in the rock, respectively. For a sensitive measurementwith sufficient accuracy, the NMR logging system 14 should be run slowlythrough the well bore 18, or, if possible, by using station-stopmeasurements at desired locations in the well bore 18.

Fluid Content in Drill-Cuttings at the Surface Condition

With the present invention, samples of formation shale in the form ofdrill-cuttings are obtained from well fluids, which are normally in theform of a drilling mud or OBM. The present invention can also beperformed with core samples of the formation shale to the extent thatsuch core samples are available from the formation shales of interest.

When the drill cuttings or rock samples are brought to the earth'ssurface, the pressure surrounding them is reduced to atmosphericpressure—about 1 atm, with a surface temperature of about 20° C. Duringthis process, the hydrocarbon gas bleeds off to equilibrate withsurrounding atmospheric pressure. If not, the large pore pressure ofhydrocarbon gas in the shale would fracture the rocks and allow the gasto escape.

At surface pressures and temperatures, the hydrocarbon is in gas statewith a density close to zero, as shown somewhere around an ellipse 36 inFIG. 2. At this low density, nuclear magnetic resonance measurement ofthe shale cuttings is not capable of detecting a signal from thehydrocarbons. In contrast, the water density at surface condition ishigher than at the reservoir conditions, as illustrated in FIG. 3 by anellipse at surface condition as compared to a rectangle indicatingexample water density at reservoir conditions. However, the waterdensity change does not alter the total water content provided the NMRmeasurement is done sufficiently quickly after the rocks are surfaced.

The water density increase of the water in shale cuttings as thecuttings are surfaced is most likely achieved by water volume reduction.Void space so formed in the cuttings can fill with hydrocarbon gas fromneighboring pores or air, if the cores are exposed to the environmentsufficiently long. It is also unlikely that water from external sourcescould enter into the rock pores, because during surfacing the pressureinside the rock is higher than atmospheric pressure at the earth'ssurface, and because these tight rocks have permeability in the nDrange. For these reasons, it is advantageous to carry out the NMRmeasurement of the formation rock, whether cuttings or core samples,either at the well-site or within a few hours surfacing to avoid waterloss or gain from the environment

The densities of methane and water in FIGS. 2 and 3 are calculated usingmeasures from industry sources or field data. The rectangles andellipses in FIGS. 2 and 3 show approximate values for the reservoir andsurface conditions, respectively. For the purposes of the presentinvention, it is not necessary to obtain or use density measures atreservoir or surface conditions for either water or gas.

An NMR measurement of the fluid within the cuttings Φ_(cuttings) ^(NMR)is then given by:Φ_(cuttings) ^(NMR)=Φ_(H) ₂ _(O)  (2)

Total Hydrocarbon Content for Gas-in-Place Estimation

The subtraction of the NMR well log and the water in drill cuttings thengives the total hydrocarbon content.Φ_(HC)=Φ_(well log) ^(NMR)−Φ_(cuttings) ^(NMR)  (3)

It should be noted that the water content can also be directly measuredfrom whole cores using whole core NMR and the total hydrocarbon isobtained from Equation (3) by replacing the last term with results ofwhole core.

NMR Measurement of Water in the Drill-Cuttings in the Presence ofDrilling Mud Physical Principle

The majority of shale gas reservoirs are drilled using drilling mud. Inthe embodiment herein described, the well bore fluid is thus regarded asdrilling mud. However, it should be understood that the methodology ofthe present invention is also suitable where other types of drillingfluids are the well bore fluid. The surfaced drill-cuttings thereforealways contain some well bore fluid, in this embodiment drilling mud,the presence of which contributes to the overall signal resulting fromnuclear magnetic resonance measurement. Although it is possible to usefluids containing no hydrogen to wash off the mud from the cuttingsbefore NMR measurement, a direct measurement of the water content ofcuttings in the presence of drilling mud is preferable. Thus, theembodiment herein described is in relation to a nuclear magneticresonance measurement method to measure water content in drill-cuttingsin the presence of drilling mud.

The nuclear magnetic resonance measurement, according to the presentinvention, is based on a physical principle that the nuclear magneticresonance transverse relaxation time T₂ of water in shales is short; andin contrast, that the majority of the fluid signal from drilling mud hasa long transverse relaxation time T₂. Depending on the particles in thedrilling mud, fluid signals from the drilling mud, when plotted, formclusters into two regions. FIG. 4 is a plot of an example nuclearmagnetic resonance transverse relaxation T₂ spectrum for arepresentative drilling mud with signal clusters 40 and 42. FIG. 5 is aplot of an example nuclear magnetic resonance transverse relaxationspectrum for a sample of shale cuttings and drilling mud, with signalclusters 50 and 52. As can be seen on comparison of FIGS. 4 and 5, thenuclear magnetic resonance transverse relaxation T₂ spectrum of water inthe shale and the short T₂ signals (T₂<4.5 ms) of a representativedrilling mud generally overlap each other. With the present invention ithas been found that the contribution of hydrogen in the drilling mudwith cuttings provides a capability to measure hydrocarbon content ofshale gas reservoir. The signal cluster of the short T₂ signals (T₂<4.5ms) at 50 in FIG. 5 indicates such a hydrogen content. The signalcluster of the short T₂ signals (T₂<4.5 ms) at 50 in FIG. 5 for drillingmud with cuttings can be seen to differ from the signal cluster 40 ofFIG. 4 for the short T₂ signals (T₂<4.5 ms) of drilling mud.

The previous discussion about hydrogen contribution in drilling mud withcuttings is also based an assumption that a ratio of the amplitudesignal clusters between the two signal clusters for the nuclear magneticresonance transverse relaxation spectrum is the same for both for puredrilling mud (FIG. 4) and for an drilling mud mixed with cuttings (FIG.5). The method of nuclear magnetic resonance measurement of water incuttings in the presence of drilling mud according to the presentinvention is based on the assumptions that water inside the shalecuttings has short nuclear magnetic resonance relaxation time, and thatthe fluid from drilling mud maintains the same magnetic resonancerelaxation time T₂ spectrum even in the presence of cuttings.

Formulation of Method

Several parameters can be measured from the NMR T₂ of a known amount(weight and volume) of drilling mud: the fluid content in unit weight ofthe pure mud X_(m) ^(w) can be measured as:X _(m) ^(w) =v _(pm) /W _(pm)  (4a)

Similarly, the fluid content in unit volume of the pure mud X_(m) ^(v)can be measured as:X _(m) ^(v) =v _(pm) /V _(pm)  (4b)

The three measurement relationships v_(pm), W_(pm), and V_(pm) are thefluid volume of the drilling mud, total weight of the drilling mud, andtotal volume of the drilling mud, respectively.

The ratio a of the short, small T₂ peaks to the long, large peaks of thetotal mud can be expressed as:α=v _(pm) ^(s) /v _(pm) ^(l)  (5)

Again, it is assumed that when drilling mud is mixed with cuttings, themeasured NMR T₂ spectrum maintains the same ratio of small T₂ peaks tolarge T₂ peaks as pure drilling mud in Equation (5).

For a sample of cuttings with drilling mud, the nuclear magneticresonance T₂ spectrum measures the total fluid: the summation of waterin the cuttings and fluid from mud:v _(c+m) =v _(w) +v _(m)  (6)in which v_(c+m), v_(w), and v_(m) are the volumes of total measuredfluid, water in the drill-cuttings, and fluid from mud, respectively.The small T₂ peak, v_(c+m) ^(s), includes the total water in thecuttings and some mud, the large T₂ peak is solely from mud (see FIG.5). With the mud contribution to the small T₂ and the large T₂ peaksremaining to be a as in Equation (5), the relation is:v _(c+m) ^(s) =v _(w) +αv _(c+m) ^(l)  (7)in which v_(c+m) ^(s) and v_(c+m) ^(l) are the fluid volume measuredfrom the small T₂ and the large T₂ regions of the NMR spectrum.

The water volume in the sample is thenv _(w) =v _(c+m) ^(s) −αv _(c+m) ^(l)  (8)and the fluid volume from mud isv _(m) =v _(c+m) −v _(c+m) ^(s) +αv _(c+m) ^(l)  (9)

Using Equation (4) and Equation (9), the weight and volume of mud in thecutting sample are:W _(m)=(v _(c+m) −v _(c+m) ^(s) +αv _(c+m) ^(l))/X _(m) ^(w)  (10a)V _(m)=(v _(c+m) −v _(c+m) ^(s) +αv _(c+m) ^(l))/X _(m) ^(v)  (10b)

In the lab or in the field, the total weight W_(c+m) and volume V_(c+m)of cutting samples can be easily measured. Using Equation (10), theweight and volume of pure cuttings (including the inherent fluid) arethen a simple subtraction of the total by the mudW _(c) =W _(c+m)−(v _(c+m) −v _(c+m) ^(s) +αv _(c+m) ^(l))/X _(m)^(w)  (11a)V _(c) =V _(c+m)−(v _(c+m) +v _(c+m) ^(s) +αv _(c+m) ^(l))/X _(m)^(v)  (11b)

The measured water in the drill cuttings in porosity-unit is

$\begin{matrix}{\Phi_{dc}^{NMR} = \frac{v_{w}}{V_{c}}} & (12)\end{matrix}$

Using Equation (8) and Equation (12), the measured water in the drillcuttings can be expressed as:

$\begin{matrix}{\Phi_{dc}^{NMR} = \frac{v_{c + m}^{s} - {\alpha\; v_{c + m}^{l}}}{V_{c + m} - {( {v_{c + m} - v_{c + m}^{s} + {\alpha\; v_{c + m}^{l}}} )/X_{m}^{v}}}} & (13)\end{matrix}$

The measured quantity values on the right of Equation (13) can bemeasured either from drill-cuttings sample or from a pure mud sample.The water in the cutting Φ_(dc) ^(NMR) is accordingly determined. Forthe determined water measure for cuttings at the surface, the measure ofhydrocarbons Φ_(HC) present in situ in the formation adjacent to theborehole is then determined during step 72 according to Equation (3)from the well log measurement in situ, Φ_(well log) ^(NMR).

In the drawings, a flowchart F (FIG. 6) indicates a basic computerprocessing sequence of the present invention for determination ofhydrocarbon content of a shale gas reservoir according to the presentinvention. As indicated at step 60, nuclear magnetic resonance well logmeasures are obtained in situ from a shale formation with the loggingsystem W as shown in FIG. 1. FIG. 3 is an example plot of the type ofdata so obtained. During step 62, in situations where cores samples arenot available for shale formation of interest, nuclear magneticresonance measures are obtained from surface evaluation of the drillingmud cuttings regarding the presence of water in the shale. In situationswhere core samples of the formation of interest are available, as analternative step 64 is performed to obtain nuclear magnetic resonancemeasures from surface testing of the water present in the core samples.As indicated at step 66, after either of steps 62 or 64, measures aredetermined during step 66 by processing as illustrated schematically inFIG. 7 to determine measures of hydrocarbons in the formation shale.

As shown in FIG. 7, computer implemented processing, according to thepresent invention, to determine measures of hydrocarbons present information shale begins with step 70, where input measures are formed ofthe drilling mud based on nuclear magnetic resonance relaxation T₂spectra. During step 72, measures are formed from the T₂ spectra of thevolume of total fluid in the samples at the surface.

In step 74, measures of the total fluid in the shale formation areobtained based on T₂ spectra. Step 76 involves obtaining measures of theweight and volume of the mud in the samples. Subsequently, in step 78, ameasure of the water Φ_(dc) ^(NMR) in the samples is determined based onthe relationship expressed in Equation (13) and the physical measuresobtained from the formations, drill cuttings and drilling mud. Themeasure of hydrocarbons Φ_(HC) in situ is then determined according tothe relation expressed in Equation (3) between total measured fluid insitu, obtained by the well logging system W, and water content of thedrill cuttings, measured at the surface.

As illustrated in FIG. 8, the data processing system D includes acomputer 100 having a master node processor 102 and memory 104 coupledto the processor 102 to store operating instructions, controlinformation and database records therein. The data processing system Dis preferably a multicore processor with nodes such as those from IntelCorporation or Advanced Micro Devices (AMD), or an HPC Linux clustercomputer. The data processing system D may also be a mainframe computerof any conventional type with suitable processing capacity such as thoseavailable from International Business Machines (IBM) of Armonk, N.Y. orother source. The data processing system D may also be a computer of anyconventional type of suitable processing capacity, such as a personalcomputer, laptop computer, or any other suitable processing apparatus.It should thus be understood that a number of commercially availabledata processing systems and types of computers may be used for thispurpose.

The computer 100 is accessible to operators or users through userinterface 106 and is available for displaying output data or records ofprocessing results obtained according to the present invention with anoutput graphic user display 108. The output display 108 includescomponents such as a printer and an output display screen capable ofproviding printed output information or visible displays in the form ofgraphs, data sheets, graphical images, data plots and the like as outputrecords or images.

The user interface 106 of the computer 100 also includes a suitable userinput device or input/output control unit 110 to provide the user accessto control or access information and database records and operate thecomputer 100. The data processing system D further includes a database112 of data stored in computer memory, which may be internal memory 104,or an external, networked, or non-networked memory as indicated at 116in an associated database 118 in a server 120.

The data processing system D includes program code 122 stored innon-transitory memory 104 of the computer 100. The program code 122according to the present invention is in the form of computer operableinstructions causing the data processor 102 to form measures ofhydrocarbon content of a shale gas reservoir according to the presentinvention in the manner that has been set forth.

It should be noted that the program code 122 may be in the form ofmicrocodes, programs, routines, or symbolic computer operable languagesthat provide a specific set of ordered operations that control thefunctioning of the data processing system D and direct its operation.The instructions of the program code 122 may be stored in the memory 104of the data processing system D, or on a computer diskette, magnetictape, conventional hard disk drive, electronic read-only memory, opticalstorage device, or other appropriate data storage device having acomputer usable non-transitory medium stored thereon. The program code122 may also be contained on a data storage device, such as a server120, as a non-transitory computer readable medium.

The data processing system D may be comprised of a single CPU, or acomputer cluster as shown in FIG. 4, including computer memory and otherhardware that makes it possible to manipulate data and obtain outputdata from input data. A cluster is a collection of computers, referredto as nodes, connected via a network. Usually a cluster has one or twohead nodes, or master nodes 102, that are used to synchronize theactivities of the other nodes, referred to as processing nodes 124. Theprocessing nodes 124 each execute the same computer program and workindependently on different segments of the grid which represents thereservoir.

From the preceding, it can be seen that the present invention determinesmeasures of the hydrocarbon content in a shale gas formation orreservoir. Nuclear magnetic resonance well logs obtain measures of thetotal fluid, including both water and hydrocarbon, in the shale of thereservoir. Nuclear magnetic resonance measurement of shale drillcuttings obtained at the surface from the same well provide measures oftotal water content of the shale.

At the surface, pressure on the drill cuttings becomes that ofatmospheric pressure, and hydrocarbon gas contained in the shalecuttings bleeds off. The remaining fluid within the shale cuttings isthen only water, which can be measured using nuclear magnetic resonancetechniques. Compensation for the effect of drilling fluids (drillingmud) on the nuclear magnetic resonance measures from the drill cuttingsis also performed. The hydrocarbon gas content of the formation shale isdetermined from the difference between formation nuclear magneticresonance well log readings and nuclear magnetic resonance measurementsfrom drill cuttings.

The present invention also provides a method for determining hydrocarboncontent of formation shale based on the measures of water contentobtained from drill cuttings. This does not require additional operationcost, such as core sampling. The present invention can be performedcontinuously to measure samples along a well while well operations arein progress, rather than a separate test based on core samples at someearlier time. The present eliminates the complicated sample preparationand preservation required to maintain fluid content in the core foraccurate results. Further, the present invention can be done at awell-site.

The present invention does not require knowledge of where and howhydrocarbon is stored in the shale pores. The present invention thusavoids the inherent problems described in detail above regarding currentwell-log based methods and/or core-measurement based methods.

The invention has been sufficiently described so that a person withaverage knowledge in the matter may reproduce and obtain the resultsmentioned in the invention herein Nonetheless, any skilled person in thefield of technique, subject of the invention herein, may carry outmodifications not described in the request herein, to apply thesemodifications to a determined structure, or in the manufacturing processof the same, requires the claimed matter in the following claims; suchstructures shall be covered within the scope of the invention.

It should be noted and understood that there can be improvements andmodifications made of the present invention described in detail abovewithout departing from the spirit or scope of the invention as set forthin the accompanying claims.

What is claimed is:
 1. A method of determining hydrocarbon gas contentof a pressurized subsurface tight gas formation at a depth of interestin the earth adjacent a well, the well having therein well fluidscomprising drilling mud and formation drill cuttings containing drillingmud, the hydrocarbon gas content being determined from nuclear magneticresonance well logging responses obtained by a nuclear magneticresonance well logging system in the well and nuclear magnetic resonanceof the well fluids by performing the steps of: (a) lowering a sondecontaining the nuclear magnetic resonance well logging system by awireline cable into the well to obtain without measuring porosity thenuclear magnetic resonance well logging responses of the pressurizedsubsurface tight gas formation in situ at the depth of interest; (b)obtaining nuclear magnetic resonance relaxation time spectra in situfrom the obtained nuclear magnetic resonance responses of thepressurized subsurface tight gas formation, the obtained relaxation timespectra indicating water and hydrocarbon fluid content in thepressurized subsurface tight gas formation; (c) forming a measure of thefluid content in the pressurized subsurface tight gas formation based onthe obtained nuclear magnetic resonance relaxation time spectra from thenuclear magnetic responses of the pressurized subsurface tight gasformation; (d) obtaining a sample of pure drilling mud for the well atthe earth surface; (e) obtaining nuclear magnetic resonance relaxationtime spectra from nuclear magnetic resonance measurements of theobtained sample of pure drilling mud for the well, the obtained nuclearmagnetic resonance relaxation time spectra indicating water content ofthe pure drilling mud for the well; (f) obtaining a sample of the wellfluid brought to the earth surface containing the pure drilling mud andformation drill cuttings from the well; (g) obtaining nuclear magneticresonance relaxation time spectra from nuclear magnetic resonancemeasurements of the obtained sample of the well fluid, the obtainedrelaxation time spectra indicating water content of the obtained sampleof the well fluid; (h) forming a measure of water content in theobtained formation drill cuttings based on the obtained nuclear magneticresonance relaxation time spectra of the obtained sample of the wellfluid; and (i) determining the hydrocarbon gas content of thepressurized subsurface tight gas formation from the formed measure ofthe water and hydrocarbon fluid content in situ of the pressurizedsubsurface tight gas formation and the formed measure of the watercontent at the earth surface in the obtained formation drill cuttings.2. The method of claim 1, wherein the pressurized subsurface tight gasformation is selected from the group consisting of tight gas shales,tight siliciclastic gas sands, and tight gas carbonates.
 3. The methodof claim 1, wherein the measure of the water content in the formationdrill cuttings comprises a measure of water content as a function ofvolume.
 4. The method of claim 1, further including the step of:compensating for the presence of drilling mud in the obtained formationdrill cuttings during the step of obtaining a measure of the watercontent in the obtained formation drill cuttings.
 5. The method of claim1, wherein the step of determining the hydrocarbon gas content of thepressurized subsurface tight gas formation from the formed measure ofthe water and hydrocarbon fluid content in situ of the pressurizedsubsurface tight gas formation and the formed measure of the watercontent at the earth surface in the obtained formation drill cuttings isperformed by computer processing and comprises computer implementedsteps of: (a) forming measures of the volume of total fluids present inthe obtained formation drill cuttings based on nuclear magneticresonance relaxation time spectra obtained from nuclear magneticresonance measures of the obtained sample of the well fluid; (b) formingmeasures of the volume of water present in the obtained formation drillcuttings based on nuclear magnetic resonance relaxation time spectraobtained from nuclear magnetic resonance measures of the obtained sampleof the well fluid; (c) forming measures of the weight and volume of theobtained sample of the well fluid; and (d) forming a measure of watercontent in the obtained sample of the well fluid.